Method for determining fluid characteristics of subterranean formations

ABSTRACT

Core samples are obtained from a plurality of differing depths in a subterranean formation. The samples are dried to effect an evaporation of the water content, leaving behind a salt precipitate. The dried samples are weighed. The salt precipitate is then leached out of the samples and the samples are again weighed, the difference in such weighings identifying the amount of salt precipitate. Alternatively, the salt content can be more accurately determined by chemical analysis of the leached solution. A measurement is made of the pore volume of the samples. From the measured weights of salt precipitates and sample pore volumes, the salt content in mass per unit volume is determined for each sample. Such salt content is plotted versus formation depth from which the core samples were taken. Trends in such plotted salt content are used to identify fluid characteristics of the formations at the in-situ reservoir conditions of pressure and temperature and at the in-situ wettability state of the reservoir.

BACKGROUND OF THE INVENTION

This invention relates to the area of oil and natural gas explorationand, more particularly, to a method for identifying regions of rockformations having significant water saturations from which hydrocarbonsmay be produced without significant attendant water production.

Subsurface reservoirs of natural gas and petroleum, hereinafter referredto generically as "hydrocarbons" are typically found trapped inpermeable geological strata beneath a layer of impermeable stratamaterial. A hydrocarbon will "float" upon any ground water presentalthough typically, a transition zone will exist between the two fluidsdue to the water being raised by capillary action of the permeablestrata material. In some regions, impermeable layers may be relativelyclosely stacked atop one another trapping thin zones of what may beessentially hydrocarbons, essentially water or mixed hydrocarbons andwater. A well bore dropped through the formation and various layers mayproduce water if tapped (completed) in a transition region or mixedhydrocarbon and water zone. The determination of water saturation aidsin the selection of completion intervals and in estimating the amount ofhydrocarbons in place. Errors in water saturation determinations canresult in (a) erroneous estimates of hydrocarbons in place, (b) thetapping of intervals with excessive amount of attendant waterproduction, originally believed they would be predominantly productiveof hydrocarbons, resulting in increased costs of production, and (c) thebypassing of intervals originally believed they would produce anexcessive amount of attendant water.

Water saturation present at various levels of a formation is typicallydetermined from interpretation of conventional electrical (i.e.,resistivity) logs taken through a borehole dropped through theformation. Water saturation of the available pore space of the formationis determined from the resistivity log measurements using the Archieequation:

    S.sub.w.sup.n =aR.sub.w /φ.sup.m R.sub.t,              (1)

where "S_(w) " is the fractional water saturation (i.e. free and boundwater of the formation expressed as a percent of the available porespace of the formation), "a" is a formation resistivity coefficient,"R_(w) " is the formation water resistivity, "φ" is the formationporosity, "R_(t) " is the formation resistivity indicated by theresistivity log, "n" is the saturation exponent and "m" is the porosityor cementation exponent. The Archie equation may be expressed in otherways and there are numerous methods in the art for determining,measuring or otherwise obtaining the various components needed topredict fractional water saturation S_(w) from the log-indicatedresistivity, R_(t), using the equation in any of its forms.

The desired oil saturation estimate S_(o) can be determined inaccordance with the following expression after solving eq. (1) for watersaturation S_(w) :

    S.sub.o =1-S.sub.w                                         ( 2)

In gas reservoirs, the gas saturation, Sg, is:

    Sg=1-Sw                                                    (3)

While such a resistivity log interpretation is used to determine watersaturation, it can be adversely affected by various factors such aslithologic changes and mineral composition, hole size, bed thickness,type of mud and filtrate invasion. Also, measurement of the saturationexponent "n" for use in solving the Archie equation for water saturationmay be unreliable.

Other available methods for water saturation determination include welltests and core analysis. Drill stem tests provide data on the type andamounts of fluids produced from selected intervals. They do not providefluid saturation data and cannot be used to define fluid-water contacts.The produced water could be due to water coning from a lower interval,or water intrusion from an upper interval through leaky casing or faultycement job. Repeat formation testers do not provide fluid saturationdata, but can furnish reliable fluid-water contact estimates underfavorable conditions. Tool problems such as differential sticking, sealfailure and probe plugging, or supercharging and threshold phenomena canlimit their applicability. Laboratory analysis on core samples cut withan oil base mud can provide a qualitative indication of water saturationabove the transition zone. Water loss due to evaporation during corehandling operations can be excessive, especially if the reservoirtemperature is relatively high. Such analysis fails to identify theoil-water contact in oil reservoirs because the filtrate can indicateoil saturation below the free water level. It is also not applicable ingas wells, especially if the bottom hole temperature is higher than theboiling point of water. Excessive core water evaporation at the surfacecan mask the actual increase in its saturation with depth, thusrendering the technique useless. Laboratory capillary pressure testsprovide data relating the capillary pressure to water saturation abovethe free water level. In applying the data to an actual reservoir, thefree water level must be determined by other means. The capillarypressure across an interface of a pair of fluids, such as oil and water,is defined as: ##EQU1## where "Po" is the oil phase pressure, "Pw" isthe water phase pressure, "δow" is the interfacial tension between theoil and water, "φ" is the contact angle of the denser phase with thesolid surface, and "r" is the radius of the capillary opening. Thebalance between capillary and gravitational forces yields:

    Pc=Δρgh                                          (5)

where "Δρ" is the density difference between water and oil, "g" is theacceleration due to gravity, and "h" is the height above the oil-watercontact. Capillary pressure data obtained at laboratory conditions usinglaboratory fluids must be converted to reservoir conditions using thefollowing relationship: ##EQU2## where the subscripts "R" and "L" denotereservoir and laboratory conditions, respectively. The ratio ofinterfacial tensions in Equation (6) is difficult to measure while thecontact angles are usually obtained using polished crystals of silica orlimestone. Consequently, the data conversion using Equation (6) may notbe adequate. In addition, core sample wettability may be different fromin-situ reservoir wettability, thus resulting in non-representativedata.

It is therefore a specific object of the present invention to provide anew method for determining subterranean formation fluid characteristicswhich overcomes the problems and limitations of the foregoing describedprior art methods.

SUMMARY OF THE INVENTION

The present invention is directed to a method for determining fluidcharacteristics of subterranean formations. More particularly, coresamples are obtained from a plurality of differing formation depths. Thesamples are dried to effect an evaporation of the water content, leavingbehind a salt precipitate. The salt content in mass per unit pore volumeis determined for each sample. The salt content is then correlated forthe plurality of core samples, such as by plotting salt content versusformation depth from which the samples were obtained. Trends in suchcorrelated salt contents are used to identify various formation fluidcharacteristics.

In one aspect, the salt content is determined in accordance with thefollowing method. The dried samples are weighed. The salt precipitate isthen leached out of the samples and the samples are again weighed, thedifference in such weighings identifying the amount of salt precipitate.A measurement is made of the pore volume of the samples. Salt content isdetermined from the measured weights of salt precipitate and core samplepore volumes.

In another method, salt is leached from the core samples and saltcontent is determined by chemical compositional and volume analysis ofthe leached solution when the salinity of the water or the amount ofprecipitated salt is too low for an accurate salt content determinationby the weight difference method.

In a further aspect, the salt content correlation with depth identifiesthe saturation profile of the subterranean formation. In a more specificaspect, a 100% fluid saturation is determined for a formation intervalover which there is no identifiable change in salt content with depth.The top of the 100% fluid saturated interval may be identified on awater table or, in the alternative, as a hydrocarbon-water interface.Also the effect of formation layering or permeability variation can beidentified. In another aspect, the information as to salt content can beused in converting laboratory derived capillary pressure data toreservoir conditions. The saturation data, so derived, can be used tocalibrate electric logs in uncored wells in the same reservoir to yieldadditional fluid saturation data.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1-3 are flow charts depicting the steps carried out in accordancewith the method of the present invention in identifying salt content ofcore samples from subterranean formations for use in identifyingformation characteristics.

FIG. 4 is a plot depicting salt content versus depth based onmeasurement of salt content in core samples taken from a plurality ofdiffering depths in a borehole traversing subterranean formations.

FIG. 5 depicts the behavior of salt content data with depth for alayered reservoir.

DESCRIPTION OF THE PREFERRED EMBODIMENT

The method of the present invention may best be understood by thefollowing descriptions taken in conjunction with the flow chart ofFIG. 1. Initially at step 10, core samples are obtained at a pluralityof differing depths from a subterranean formation during drilling forpetroleum exploration and production. These core samples are then to beanalyzed for salt content in accordance with the present invention todetermine fluid saturation in oil and gas reservoirs and to determinehydrocarbon-water contact. As water saturation increases with depth, sodoes salt content. If overbalance conditions and filtrate loss are keptto a minimum, the salt content will be a function of water saturation.It will achieve constancy below the 100% water level.

Preferably the whole core samples are frozen at the rig site and keptfrozen until the start of analysis. Freezing prevents mixing of mudfiltrate with formation water and suppresses ionic diffusion. It isrecommended even if the coring fluid is oil-base to guard against mudbreakdown that may cause the filtrate to be water instead of oil.Concentric, vertical core plugs are cut at selected depths using liquidnitrogen as bit coolant. The size of the plugs will vary depending uponthe degree of mud filtrate invasion, rock porosity, salinity of thewater and method of analysis for salt content. Filtrate invasion can beestimated by tagging the coring fluid with a suitable tracer such astritium or fluorescein dye and analyzing for the tracer concentration atvarious distances from the center of the core. If invasion is low, atwo-inch diameter by two-inch long plug is adequate for rocks withaverage porosity of 15% and water salinity in excess of 100,000 partsper million. The diameter and length of the plugs may vary to suitparticular conditions. At Step 11, the plugs are introduced into aconventional, controlled-temperature vacuum oven utilizing a temperatureof about 85° C. The plugs are dried until all the water content hasevaporated, leaving behind its salt precipitate. This may be indicatedwhen there is not further weight change with continued drying. Followingdrying, the plugs may be cooled in a conventional desiccator.

It is then necessary to determine the salt content (i.e., precipitate)in each core plug at step 12. In one method, as shown in FIG. 2, theplugs are weighed at step 20 and then the salt is leached from the plugsat step 21 with any of a plurality of acceptable solvents which will notattack, alter or destroy the structure of the core plugs. Distilledwater can be used as a solvent in carbonate and sandstone rocks that donot contain hydratable clays. Where clays are present, methyl alcoholcan be used. Following such leaching, the plugs are again dried at about85° C. in a vacuum oven, cooled in a desiccator and weighed at step 22.The weight difference for each plug as obtained in step 23 representsthe salt mass of such plug. When core plugs contain oil or gascondensate, the weighing step would consist of oil extraction from theplugs using a suitable solvent such as toluene. Conventional methods fordrying and oil extraction are described in API Recommended Practice ForCore-Analysis Procedure, American Petroleum Institute, RP 40, 1960.Flushing of cores by direct pressuring of solvent (flow-through) ispreferred because the same apparatus can be used for oil extraction orsalt leaching by using the appropriate solvents. To record the saltcontent in terms of mass per unit of pore volume, it is next necessaryto measure the aggregate volume of the samples' void or pore spaces,i.e., pore volume, at step 24. Methods for making such a pore volumedetermination are described in API Recommended Practice for CoreAnalysis Procedure, API, RP 40, 1960, pg. 16-45 and PetroleumEngineering Handbook, Howard B. Bradley, Editor, Soc. of PetroleumEngineers, 1987, Chapter 26. Salt content is then recorded at step 12 inunits of milligrams per milliliters of pore volume. It is to be notedthat this is not a salinity measurement in parts per million.

An alternate method to that shown in FIG. 2 for determining salt contentis shown in FIG. 3. This method may be applied when the core samples arefrom reservoirs containing low salinity formation water or high oil orgas saturation (low water saturation). These samples may not yield anaccurately measurable salt content by the weight difference techniquedescribed above. In such instances, and to avoid using excessively largecore plugs, the salt content can be derived by other, more accuratetechniques. As in the alternate method described above, the salt isleached from the dried core plugs at step 30. The solvent containing theleached salts can be analyzed at step 31 using chemical analysis, suchas inductively coupled plasma atomic emission spectroscopy (ICP) andtitrimetric techniques. These techniques are described in "StandardMethods for the Examination of Water and Waste Water," Am. Public HealthAssociation, Am. Water Works Association, and Water Pollution controlFederation, 16th Edition (1985), and API Recommended Practice forAnalysis of Oil Field Waters, American Petroleum Institute, RP 45, 1968.(When methanol is used as the solvent, it can be replaced by distilledwater by vaporizing and redissolution.) From the compositional analysisand volume of the solution, the salt content in terms of mass per unitvolume can be recorded at step 32. (In certain areas where the ratiobetween the total dissolved solids and a particular reference element orion species such as chloride is known, the determination of the chloridecontent simplifies the analysis procedure.)

Referring again to FIG. 1, the salt contents of such core plugs are nowcorrelated, such as by plotting at step 13. Such a plot is shown in FIG.4 where it can be observed that salt content increases with depth. Thisis attributed to the fact that water saturation increases with depth andthere is a one-to-one correspondence between water saturation and saltcontent. When the formation depth reaches a water table, i.e., a pointof 100% water saturation, such as at a hydrocarbon-water contact, themeasured salt content no longer increases.

Consequently such a correlation of salt contents of a plurality of coresamples taken from differing borehole depths can be used at step 14 toidentify formation characteristics. For example, a plot of salt contentversus depth provides a saturation profile with formation depth. Theintersection of the best fit line passing through the data points whichindicate constant water saturation, with the best fit curve passingthrough the data points which indicate decreasing water saturation, isthe hydrocarbon-water contact. The highest salt content indicated on thegraph of FIG. 4 would correspond to a water saturation of 100%. Becauseof the linear, one-to-one relationship between water saturation and saltcontent, the abscissa can be converted to a water saturation scaleranging from 0-100%. Using Equation 5, the height above the water table,being zero at the water table, can be used to derive values forcapillary pressure, thus resulting in a capillary pressure-saturationrelationship at the in-situ state of reservoir wettability and at thein-situ reservoir conditions of pressure and temperature. Comparison ofthe resulting capillary pressure at one or more intermediate saturationpoints with laboratory-derived data on similar rock samples can resultin derivation of the correct conversion factor for use in Equation 6,namely, (δow COSθ)_(R) /(δow COSθ)_(L). The effect of layering orpermeability variation can be revealed from the salt content data ofFIG. 5 which illustrates salt content versus depth for a reservoircomposed of two layers where layer 1 possesses a larger permeabilitythan layer 2. If rock properties vary such that the water table and/orthe capillary retention properties of the rocks vary with depth, thedata can reveal such variations in lithology with a relatively highdegree of resolution. Furthermore, correlation of the data with electriclogs can yield the correct values for the saturation exponent(Equation 1) that would result in a match between log-derivedsaturations and salt content-data-derived saturations. Such correlationscan be used in other logged, but not cored, wells.

The derived water saturation data can be easily corrected if theformation water salinity varies with depth. The correct water saturationwould be obtained by multiplying the apparent saturation by the ratio ofthe water salinity in parts per million at a particular depth to that ator slightly below the hydrocarbon-water contact. More simply, thecorrect water saturation in percent is equal to the ratio of the actualsalt content in mass per unit pore volume to the equivalent salt contentin the same unit pore volume when it is 100% filled with brine (thelatter being derived from known water salinity and specific gravity)multiplied by 100.

The method of the present invention has the advantage that coring fluidis not important, provided filtrate loss is low and further, becausewater evaporation losses from the difference in the high temperature andpressure conditions of the subterranean formation to ambient conditionsin the laboratory are not relevant because the salt precipitates insidethe core sample.

While the foregoing has described the method of the present inventionfor identifying formation characteristics from salt content, it is to beunderstood that various modifications to the disclosed method may becomeapparent to one skilled in the art without departing from the scope andspirit of the invention as set forth in the appended claims.

I claim:
 1. A method for determining the fluid characteristics of subterranean formations, comprising the steps of:(a) obtaining core samples from a plurality of differing depths with said subterranean formations, (b) drying said plurality of core samples to effect an evaporation of the water content of said core samples, (c) determining the salt content of said plurality of core samples, (d) correlating the determined salt content of said plurality of core samples with the differing depths from which said plurality of core samples were obtained, and (e) determining the fluid characteristics of said subterranean formations at in-situ reservoir conditions, of pressure and temperature and at the in-situ state of reservoir wettability, from trends identified in the correlation of the salt contents of said plurality of core samples with depth.
 2. The method of claim 1 wherein the step of determining salt content comprises the steps of:(a) measuring the weight of said dried plurality of core samples, (b) leaching salt from said dried plurality of core samples, (c) measuring the weight of said leached plurality of core samples, (d) determining the weight of salt leached from said core samples from the weight difference of said dried core samples and said leached core samples, (e) measuring the pore volume of said plurality of leached core samples, and (f) determining the salt content of said plurality of core samples in terms of the weight of salt leached from said core samples and the measured pore volumes of said core samples.
 3. The method of claim 1 wherein the step of determining salt content comprises the steps of:(a) leaching salt from said dried plurality of core samples, (b) performing chemical compositional and volume analysis of the solution leached from said core samples, and (c) determining the salt content of said plurality of core samples in terms of the weight of salt leached from said core samples and the volume of said leached salt as identified from said chemical analysis.
 4. The method of claim 1 further comprising the step of determining fluid saturation in said subterranean formations from an identifiable trend in said salt content correlation.
 5. The method of claim 4 wherein 100% fluid saturation is determined for a formation interval over which there is no identifiable change in salt content with depth.
 6. The method of claim 5 wherein the top of a 100% fluid saturated interval is identified as the water table.
 7. The method of claim 5 wherein the top of a 100% fluid saturated interval is identified as the depth of a hydrocarbon-water interface.
 8. The method of claim 4 wherein said determined fluid saturation provides for a capillary pressure versus saturation relationship at the in-situ reservoir conditions of pressure and temperature and at the in-situ state of reservoir wettability.
 9. The method of claim 4 wherein correlation of said determined fluid saturation exponents that are used to calibrate said electric logs in uncored wells in the same reservoir to provide additional fluid saturation determinations.
 10. The method of claim 1 wherein the drying of said plurality of core samples is completed after the entire water content of said core samples has evaporated, leaving behind its salt precipitate.
 11. The method of claim 10 wherein said drying is completed when there is no further weight change in said core samples. 